1. Field of the Invention
The present invention pertains to the drilling of wells, such as oil and gas wells and, more particularly, to controlling the usage of a well drill bit and other aspects of execution of a well drilling plan. Before a well is drilled, a plan is developed for at least roughly projecting the timing of such activities as the replacement of the drill bit, changing the weight of the drilling mud, setting casing, etc. "Timing" in this context can literally refer to hours of operation with reference to the replacement of a drill bit, but can also connote the depth at which certain actions are taken, especially changes in mud weight and the setting of casing.
It is rare to follow such a plan precisely. Since a certain amount of projection, or even guess work, is involved in developing the plan, the plan must sometimes be modified based on actual experience while drilling the well. That is to say, decisions must constantly be made as to whether or not to continue following the plan, i.e. maintain the plan, or modify the plan by taking a planned action sooner or later, or at a greater or lesser depth, than originally planned.
For example, drill bits wear in use, and eventually to such a degree that it becomes ineffective to continue drilling with the same bit, and that bit must be replaced. However, replacing the bit requires a "trip" of the entire drill string, which is an expensive proposition, particularly if the well has been drilled to a substantial depth. Therefore, it is highly desirable to avoid tripping the string prematurely, i.e. when the bit still has a good amount of useful life remaining. On the other hand, it is important to replace the bit promptly when it has become ineffective.
Unlike the prior art known to Applicants, the present invention models wear of a given drill bit as a function primarily of formation abrasiveness, and more specifically, the abrasiveness of the formation which has actually been drilled by that bit.
In addition, the present invention provides an improved way of determining the pore pressure, which can, in itself, be used to evaluate other aspects of the well drilling plan, e.g. whether or not to change mud weight and when to set casing.
2. Description of the Prior Art
Various means have been devised for attempting to predict or actively determine bit wear. Some of these have addressed the determination of wear in the bearings of the drill bit, so that there remained a need for a means for determining wear of the outer drilling structure, typically teeth, of the bit.
Some of the most common means currently used to attempt to predict bit wear simply proceed on the assumption that the formation which will be drilled in a current well will be similar to that experienced in a nearby well which has already been drilled, so that the rate of bit wear will be comparable. No matter how sophisticated these systems may be, they are not as accurate as they might be because the lithology in nearby wells may vary; in other words, the basic hypothesis of such a system is not always valid.
For example, U.S. Pat. No. 4,914,591 to Warren discloses a system in which a rock compressive strength log for a first well is generated. While a second such well is being drilled, another such log is generated and compared with the first. On the assumption that the formation features of the two wells are similar, when a significant deviation between the two logs is observed, it is assumed that the bit is worn or damaged. Thus, this system assumes that, if the rock compressive strength "feels" higher, the explanation must be that the bit is worn or damaged. It does not take into account that the bit may be in good shape, but rock at the depth in question in the second well is in fact stronger than rock at the same depth in the first well. The system does not attempt to determine abrasiveness of the rock in the second well and model current bit wear thereon.
Other examples are given in a paper by K.L. Mason, titled "Tricone Bit Selection using Sonic Logs," SPE 13256.
Still other systems have contrived to determine the actual wear of the drilling structure of a bit currently in use. These have also had room for improvement.
More particularly, a number of systems have provided means, literally triggered by physical wear, to somehow change the fluid flow characteristics of the drilling mud when the bit has become worn to a certain degree. For example, U.S. Pat. No. 3,058,532 utilizes a probe or detector which directly detects wear of the outer surface of a drill bit. When this probe or detector detects wear beyond a certain limit, a signal, detectable at the surface, is produced.
In U.S. Pat. No. 2,560,328, a blind (closed ended) tube communicating with the interior of the bit is positioned to be worn by the rock being drilled along with the bit's cutting structure. When this tube is worn through, its blind or closed end is opened, so that drilling mud can pass therethrough, and the operator will detect a change in the pressure of the drilling mud.
Similar schemes are described in U.S. Pat. No. 2,580,860, No. 4,785,895, No. 4,785,894, No. 4,655,300, No. 3,853,184, and No. 3,363,702. U.S. Pat. No. 2,925,251 is similar except that the signal produced is electrical, rather than fluidic.
U.S. Pat. No. 3,578,092 pertains to a system for determining wear of a stabilizer blade in which that blade encapsulates a pocket of crypton which is released when a certain degree of wear occurs.
The above systems are all susceptible to inaccuracies and/or mechanical failures.
U.S. Pat. No. 4,030,558 involves magnetically recovering and analyzing bit fragments which are carried back to the surface in the drilling mud. The analysis involves observation under a microscope. It is therefore tedious, time consuming and requires a fair degree of specialization by the analyst.
U.S. Pat. No. 3,345,867 does attempt to extrapolate bit wear from ongoing drilling conditions. In particular, the ratio between the bit rotational speed and the cone rotational speed, in a roller cone type bit, is calculated. The system relies on the idea that variations in that ratio give an indication of the wear of the teeth on the outside of the cones. The cone rotational speed is determined by observing the frequency response of the vertical accelerations in the drill string. This system is too simplistic and may not be as accurate as is possible. It does not attempt to analyze the lithologies actually being drilled nor to determine bit wear as a function of abrasion by the formation which has been drilled.
Other systems which attempt to utilize real-time parameters but which, again, are too simplistic and fail to take actual formation characteristics into account, are disclosed in U.S. Pat. No. Re. 28,436 and U.S. Pat. No. 4,773,263.
U.S. Pat. No. 4,926,686 to Fay discloses a system for determining bit wear dynamically, i.e. while the bit is drilling. The basis for this is variation in a curve obtained by plotting torque as it varies with weight on bit, i.e. the effect the wear has on the operation of the apparatus. Data about the formation appears to be derived prior to drilling the well in question. There is no dynamic determination of a wear-affecting variable of the formation, such as abrasiveness. Rather, wear is modelled as a function of drilling parameters affected by wear.
A similar approach is taken in a paper by T.M. Burgess and W.G. Lesso, titled "Measuring Wear of Milled Tooth Bits Using MWD Torque and WOB," SPE/IADC 13475.
Similarly, U.S. Pat. Nos. 2,669,871, No. 3,774,445, and No. 3,761,701 all attempt to model bit wear as a function of various drilling values, such as weight-on-bit, rate of penetration, revolutions per minute, and time. However, these models fail to take into account the abrasiveness of the lithology being drilled, which is a highly significant factor, particularly when attempting to model wear of the exterior, i.e. teeth, of a bit. The same is true of the method disclosed in U.S. Pat. No. 4,685,329, which considers torque-on-bit, weight-on-bit, rate of penetration and revolutions per minute.
U.S. Pat. No. 2,096,995 discloses a system which does attempt to project certain information about the lithology being drilled. However, this information is not used to attempt to determine or model bit wear, and, on the contrary, the patent treats bit wear as only a relatively minor factor which might be taken into account in connection with the basic lithology determination.
U.S. Pat. No. 4,064,749 teaches a system directed at determining formation porosity from drilling response. The patent does mention a determination of "tooth dullness." The operational input for this determination is quite different from that of the present invention, and it would appear that the determination lacks adequate precision, as it will only determine dulling in excess of a bit grade No. 5.
U.S. Pat. No. 4,794,535 involves an attempt to determine when a bit should be changed using a mathematical model. However, this model, which is based on bit economics, simply uses the formation abrasion calculated from the previous bit run; it does not attempt to model bit wear based on the lithology actually drilled by the bit in question. Nor does this method include as much input as to the bit geometry as does the present invention, and to that extent, the results are less precise.
U.S. Pat. No. 3,898,880 is even less sophisticated. In essence, wear is predicated simply as a function of time, with no adjustment for the lithology being drilled, nor for the actual bit geometry.
U.S. Pat. No. 4,627,276 probably comes closer to any of the above to effectively utilizing lithology actually drilled in a given bit run in some type of wear determination. However, the system only "kicks in" to produce such a determination when the bit is drilling in shale. At that time, the bit may have already been significantly worn by having drilled through sandstone. By way of contrast, the present invention continually interprets the nature of the lithology currently being drilled, and continually determines current bit wear, taking into account all the lithology which has been drilled up to that point.
A paper entitled "Use of Single-Cutter Data in the Analysis of PDC Bit Designs: Part II/Development and Use of the PDC Wear COMPUTER CODE" by D.A. Glowka and published in the August 1989 issue of JPT (Journal of Petroleum Technology), describes a technique for predicting wear of the cutters of PDC type drag bits using formation abrasion and sliding distance of a tooth as primary factors. However, the system was developed through laboratory experiments where the lithologies were known, and the article does not teach any means for analyzing lithology drilled in real-time. Among other differences, this system also utilizes additional parameters which, while feasible in laboratory analysis, would be very difficult to implement in real-time, e.g. the depth of cut of each tooth or cutter.
Considered cumulatively, the prior art shows that determinations of bit wear are a significant problem, to which much attention has been given, but apparently without any really definitive solution. More specifically, it appears that the known methods generally suffer from an inability to accurately determine bit wear on the basis of the nature, and more specifically abrasiveness, of the lithology actually drilled by a given bit.
Turning to the pore pressure aspect, U.S. Pat. No. 4,981,037 to Holbrook et al and a related SPE paper No. 1666, "Petrophysical-Mechanical Math Model for Real-time Wellsite Pore Pressure/Fracture Gradient Prediction" describe a way of determining pore pressure on the basis of lithology actually drilled in the well in question. However, this prior system views pore pressure as a function of absolute rock properties. Furthermore, it is limited to a determination of the pore pressure at a site a significant distance above the then current location of the bit, e.g. seven to fifty feet.